Fuel compositions comprising natural gas and dimethyl ether and methods for preparation of the same

ABSTRACT

The invention is directed to compositions comprising mixtures of natural gas and dimethyl ether suitable for use as fuel compositions, and particularly to blends of dimethyl ether and a natural gas derived from LNG produced in an LNG process. The dimethyl ether can be added, for example, to a lean natural gas to improve the heat value thereof, and in embodiments, the dimethyl ether is conveniently derived from low value CO 2  contaminants present in a raw natural gas stream used to prepare LNG. Also disclosed are methods to prepare the mixtures.

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims benefit of U.S. Provisional ApplicationSer. No. 60/458,213, filed Mar. 27, 2003, the teachings of which areincorporated herein by reference in their entirety.

[0002] Filed concurrently on even date herewith is the applicationentitled “Integrated Processing of Natural Gas Into Liquid Products”,Attorney's Docket No. 37,488-00, which claims benefit from U.S.Provisional Application Ser. No. 60/458,005, filed Mar. 27, 2003. Theteachings of these applications are also incorporated herein byreference.

FIELD OF THE INVENTION

[0003] The present invention relates to fuel compositions derived fromnatural gas having improved heating values, and in particular to fuelcompositions comprising blends of dimethyl ether (DME) and natural gas,including natural gas components derived from liquefied natural gas(LNG), and also to methods for preparation of the fuel blends.

BACKGROUND OF THE INVENTION

[0004] Natural gas generally refers to rarefied or gaseous hydrocarbons(comprised of methane and light hydrocarbons such as ethane, propane,butane, and the like) which are found in the earth. Non-combustiblegases occurring in the earth, such as carbon dioxide, helium andnitrogen are generally referred to by their proper chemical names.Often, however, non-combustible gases are found in combination withcombustible gases and the mixture is referred to generally as “naturalgas” without any attempt to distinguish between combustible andnon-combustible gases. See Pruitt, “Mineral Terms-Some Problems in TheirUse and Definition,” Rocky Mt. Min. L. Rev. 1, 16 (1966).

[0005] Natural gas is often plentiful in regions where it isuneconomical to develop those reserves due to lack of a local market forthe gas or the high cost of processing and transporting the gas todistant markets.

[0006] It is common practice to cryogenically liquefy natural gas so asto produce LNG for more convenient storage and transport. A fundamentalreason for the liquefaction of natural gas is that liquefaction resultsin a volume reduction of about {fraction (1/600)}, thereby making itpossible to store and transport the liquefied gas in containers at lowor even atmospheric pressure. Liquefaction of natural gas is of evengreater importance in enabling the transport of gas from a supply sourceto market where the source and market are separated by great distancesand pipeline transport is not practical or economically feasible.

[0007] In order to store and transport natural gas in the liquid state,the natural gas is preferably cooled to −240° F. (−151° C.) to −260° F.(−162° C.) where it may exist as a liquid at near atmospheric vaporpressure. Various methods and/or systems exist in the prior art forliquefying natural gas or the like whereby the gas is liquefied bysequentially passing the gas at an elevated pressure through a pluralityof cooling stages, and cooling the gas to successively lowertemperatures until liquefaction is achieved. Cooling is generallyaccomplished by heat exchange with one or more refrigerants such aspropane, propylene, ethane, ethylene, nitrogen and methane, or mixturesthereof. The refrigerants are commonly arranged in a cascaded manner, inorder of diminishing refrigerant boiling point. For example, processesfor preparation of LNG generally are disclosed in U.S. Pat. Nos.4,445,917; 5,537,827; 6,023,942; 6,041,619; 6,062,041; 6,248,794, and UKPatent Application GB 2,357,140 A. The teachings of these patents areincorporated herein by reference in their entirety. In general, the LNGemployed in the practice of the present invention may be preparedaccording to any of the known LNG processes.

[0008] Natural gas produced from some subterranean reservoirs cancomprise a very lean gas, i.e., a gas wherein the hydrocarbon content ispredominately methane with only relatively minor levels (less than about3 mol %) of higher hydrocarbons therein such as those boiling greaterthan methane, typically C₂-C₅ hydrocarbons. Further, the natural gasindustry, including those who produce LNG, typically remove the higherhydrocarbons in the natural gas as produced, and direct them to otheruses due to their higher economic value in the marketplace. As a result,when such lean natural gas is used as a feed to produce LNG, theresulting LNG can have an undesirably low heating value, such as lessthan 1000 BTU/SCF. Local market demand for LNG typically requires ahigher heating value, such as from about 1000 BTU/SCF to about 1200BTU/SCF and higher.

[0009] Historically, to meet the market demand in some markets whereincreased LNG heating value is desired, the LNG product heating valuehas been increased by blending it with selected amounts of lighthydrocarbons, such as ethane, propane, or butanes, which are most oftensupplied as a mixture typically referred to as liquefied petroleum gasor “LPG”. The amount of LPG blended therein is that sufficient to meetthe market specification. This practice may not always be economical forthe LNG producer and/or LNG consumer. For example, if the natural gas isvery lean or a source of LPG is not readily available at the site wherethe natural gas is converted to LNG or where the LNG is re-gasified foruse by a consumer thereof, then LPG must be shipped to such sites. Atpresent, a significant quantity of LNG is consumed in the Asian Pacificmarkets and to meet heating value specifications in this market for someLNG products, LPG is shipped long distances for blending with low heatvalue LNG products. As a result, this practice increases the costsassociated with such LNG products.

[0010] As can be seen, it would be desirable to develop alternatives soas to improve the heat value of natural gas and in particular, toutilize lean natural gas sources and increase the heat value of LNGproduced therefrom without relying on expensive transport of LPGmaterials. Such alternatives could make such natural gas supplies a moreeconomical and commercially attractive energy resource from theperspective of both LNG producers and consumers.

SUMMARY OF THE INVENTION

[0011] The foregoing objectives may be attained by the presentinvention, which in one aspect relates to a composition comprising ablend of natural gas and dimethyl ether. The composition may comprise ablend of natural gas and dimethyl ether in a liquid form, such as thatobtained by condensing both natural gas and dimethyl ether in a LNGprocess; or in a vapor form, such as that obtained by mixing aregasified LNG product with dimethyl ether in the vapor phase, or bymixing a produced natural gas with dimethyl ether in the vapor phase.

[0012] In another aspect, the invention relates to a method forpreparing a fuel blend comprising natural gas and dimethyl ether,wherein the method comprises mixing a natural gas component and dimethylether.

[0013] In embodiments, the method further comprises preparing thenatural gas component by the steps of:

[0014] pre-treating a natural gas stream comprising acid gases, waterand other contaminants therein to remove at least a portion of thecontaminants therefrom and provide a natural gas feed;

[0015] cooling the natural gas feed in a LNG process to liquefy at leasta portion of the natural gas component and thereby produce a LNGproduct; and

[0016] re-gasifying the LNG product to obtain the natural gas component.

[0017] In further embodiments of the foregoing, the method alsocomprises adding the following steps of:

[0018] providing dimethyl ether; and

[0019] mixing the dimethyl ether with the natural gas component in thevapor phase to obtain the fuel blend.

[0020] Where the dimethyl ether and natural gas are mixed in the vaporphase, the dimethyl ether may be added in any amount to achieve adesired higher heating value, provided, however, that the resulting fuelblend will be maintained below the hydrocarbon dew point for thepressure and temperatures at which the fuel blend is to be stored orconveyed, typically those conditions being specified for the pipeline inwhich the fuel blend is to be conveyed to market or the ultimate userthereof. Typically, the amount of dimethyl ether added will be less than25 mol % based on the total fuel blend, and beneficially from 10-15 mol% of the total fuel blend.

[0021] In the above-described embodiments of the method, it may beconvenient to re-gasify the LNG product and mix it with dimethyl etherat a site remote from a location where the natural gas feed originates,and more particularly, at a location near the market for the fuel blend.

[0022] In other embodiments where the dimethyl ether is mixed with anatural gas in a LNG process, the method further comprises:

[0023] pre-treating a natural gas stream comprising acid gases, waterand other contaminants therein to remove at least a portion of thecontaminants therefrom and provide a natural gas feed for the LNGprocess;

[0024] mixing the dimethyl ether into the natural gas feed within theLNG process at a temperature above −220° F. (−140° C.) and in an amountsuch that the dimethyl ether does not solidify and form a separate solidphase during liquefaction of the natural gas feed in the LNG process;

[0025] cooling the resulting natural gas and dimethyl ether mixturewithin the LNG process to a temperature of from about −240° F. (−151°C.) to about −260° F. (−162° C.) or less so as to liquefy at least aportion of the mixture and thereby produce a blended liquid product atsubstantially atmospheric pressure; and

[0026] re-gasifying the blended liquid product to produce the fuelblend.

[0027] Where the dimethyl ether is mixed with the natural gas feed in aLNG process, the mixing may be in the vapor phase, the liquid phase, orboth, and the dimethyl ether may be added in an amount to achieve adesired higher heating value when the blended liquid product isregasified, provided, that the amount of dimethyl ether added will notresult in solidification of the dimethyl ether in the blended liquidproduct, typically 5 mol % dimethyl ether or less based on the totalblended product.

[0028] The blended liquid product according to the foregoing method canbe conveniently re-gasified just prior to use to produce the desiredfuel blend, and in particular, at a site remote from a location wherethe natural gas stream originates or the blended liquid product isproduced, such as a location near the market for the fuel blend.

[0029] In another aspect, the invention is directed to a method forpreparing a fuel blend comprising natural gas and dimethyl ether. Themethod comprises:

[0030] pre-treating a natural gas stream comprising acid gases, waterand other contaminants therein to remove at least a portion of thecontaminants therefrom and provide a natural gas feed;

[0031] cooling the natural gas feed in a LNG process to liquefy at leasta portion of the natural gas component and thereby produce a LNGproduct;

[0032] providing dimethyl ether;

[0033] re-gasifying the LNG product to obtain the natural gas component;and

[0034] mixing the dimethyl ether with the natural gas component in thevapor phase to obtain the fuel blend.

[0035] In the above-described embodiment, it may be convenient tore-gasify the LNG product and mix it with dimethyl ether at a siteremote from a location where the natural gas feed originates or the LNGproduct is produced, and more particularly, at a location near themarket for the fuel blend.

BRIEF DESCRIPTION OF THE DRAWINGS

[0036]FIG. 1 is a schematic process flow sheet illustrating a processfor preparing methanol with a feed that includes all or a portion of CO₂contaminant that may be separated and recovered from a lean natural gasproduced from a subterranean reservoir. The methanol may then be reactedto form DME, which in turn can then be mixed with natural gas accordingto the invention to form a fuel blend composition of higher heat valuerelative to the lean natural gas.

[0037]FIG. 2 is a simplified block flow diagram illustrating anembodiment of the present invention, wherein a lean natural gas isblended with DME in the vapor phase and then condensed in a natural gasliquefaction process to produce a blended liquid LNG/DME product. Theblended liquid LNG/DME product may then be conveniently transported to adistant market, and later re-gasified at a site remote from the locationwhere the blended liquid product is produced or liquefied to provide afuel composition with greater heat value relative to the lean naturalgas.

[0038]FIG. 3 is a simplified block flow diagram illustrating anotherembodiment of the present invention, wherein LNG produced from a leannatural gas and DME are re-gasified and mixed in the vapor phase toproduce a fuel blend according to the invention. The LNG and DMEemployed may be manufactured at a location where the raw natural gasused to make the LNG is produced from a subterranean reservoir. The LNGand DME can then be conveniently transported to a distant market, andlater re-gasified and mixed to provide a fuel blend composition withgreater heat value relative to the lean natural gas.

[0039]FIG. 4 is a table illustrating data in connection with Examples1-3 and Comparative Examples A-D discussed hereinafter.

[0040]FIG. 5 is a graph illustrating, on the left-side vertical axis—thehigher heating value (HHV) in terms of BTU/scf; and on the right-sidevertical axis—hydrocarbon dew point in terms of ° F., for various blendsof natural gas and DME according to the invention. The line withdatapoints illustrated by round dots shows the HHV calculated forvarious blends. The curve with datapoints shown as squares shows thehydrocarbon dew point at a pressure of 14.7 psia calculated for variousblends of natural gas and DME, while the curve with datapoints shown astriangles shows the hydrocarbon dew point calculated at a pressure of500 psia for the blends.

DETAILED DESCRIPTION OF THE INVENTION

[0041] The natural gas component employed in practicing the presentinvention may be any light hydrocarbon-containing gas that can be usedas a fuel gas, advantageously it is a lean natural gas as previouslydiscussed with a relatively low heating value, such as less than 1000BTU/scf.

[0042] Typically, as mentioned above, there many natural gas reservoirsthat contain significant amounts of non-combustible CO₂ gas therein. Atpresent, commercial scale LNG plants use processes which generallyrequire nearly complete removal of acid gases, including CO₂, from thefeed gas to the LNG process. In the past, the CO₂ extracted from thefeed gas has been simply vented to the atmosphere. However, currentconcerns over global warming, internationally driven initiatives toreduce greenhouse emissions, and other environmental factors makeventing of such CO₂ undesirable.

[0043] In general, where the natural gas component is derived from LNG,the LNG employed in the practice of the present invention may beprepared according to any known LNG process. For example, processes forpreparation of LNG generally are disclosed in U.S. Pat. Nos. 4,445,917;5,537,827; 6,023,942; 6,041,619; 6,062,041; 6,248,794, and UK PatentApplication GB 2,357,140 A, the teachings of which are incorporatedherein by reference in their entirety. Another LNG process which isintegrated with other processes to produce liquid products from naturalgas is also disclosed in co-pending U.S. patent application Ser. No.10/051,425, filed Jan. 18, 2002, wherein flash gas from the LNG processis employed to make other liquid products, such as methanol, dimethylether, hydrogen, and Fischer-Tropsch products. The teachings of thisapplication are also incorporated herein by reference in their entirety.

[0044] The natural gas feed contemplated herein for use in preparing theLNG in an LNG process generally comprises at least 50 mole percentmethane, preferably at least 75 mole percent methane, and morepreferably at least 90 mole percent methane. The balance of natural gasas mentioned briefly above generally comprises other combustiblehydrocarbons such as, but not limited to, lesser amounts of ethane,propane, butane, pentane, and other higher boiling hydrocarbons, andnon-combustible components such as carbon dioxide, hydrogen sulfide,helium and nitrogen.

[0045] The presence of heavier hydrocarbons such as ethane, propane,butane, pentane, and hydrocarbons boiling at a boiling point abovepentane can optionally be reduced in the natural gas feed to an LNGprocess through gas-liquid separation steps, in the event suchhydrocarbons have greater value for use outside the production of LNG.Hydrocarbon boiling at a temperature above the boiling point of pentaneor hexane is generally directed to crude oil. Hydrocarbon boilingsubstantially at a temperature above the boiling point of ethane andbelow the boiling point of pentane or hexane is generally removed fromthe methane feed to the LNG process, and is sometimes considered to benatural gas liquids or “NGLs”. These heavier hydrocarbons are alsotypically removed from natural gas produced from a formation inpreparation of a natural gas fuel.

[0046] For most markets, it is also desirable to minimize the presenceof non-combustibles and contaminants in the LNG or fuel gas, such ascarbon dioxide, helium and nitrogen and hydrogen sulfide. Depending onthe quality of a given natural gas reservoir (which may contain as muchas 50% to 70% carbon dioxide), the natural gas may be pre-processed at anatural gas plant for pre-removal of such of the above components or maybe conveyed directly to an LNG plant for pre-processing prior tomanufacture of LNG products. Accordingly, the natural gas feed to theLNG process is generally pre-treated, prior to liquefaction in the LNGprocess, to separate the CO₂ and other acid gases therein. As mentionedbelow, the CO₂ removed from a natural gas can then be recovered and usedto make methanol, and the methanol converted to DME, for use inaccordance with the present invention.

[0047] Pretreatment generally begins with steps commonly identified andknown in connection with conventional LNG production, including, but notlimited to, removal of acid gases (such as H₂S and CO₂), mercaptans,mercury and moisture from the natural gas stream, as further discussedherein.

[0048] U.S. Provisional Application Ser. No. 60/458,005 filed on Mar.27, 2003, which is incorporated herein by reference in its entirety,discloses a process for integration of LNG processes with otherprocesses to prepare liquid products from natural gas, such as amethanol production process comprising conversion of the natural gas tosynthesis gas (H₂ and CO) and then conversion of the synthesis gas tomethanol. In the disclosed process, the non-combustible CO₂ gasseparated from the raw natural gas prior to being fed to the LNG processis recovered and subsequently utilized in the production of methanol.The CO₂ can be converted to methanol by any known synthesis method, suchas those illustrated for example in Vol. 16, pages 537-556 of theKirk-Othmer Encyclopedia Of Chemical Technology (4^(th) Ed.—John Wiley &Sons Inc. New York, N.Y. 1995), the teachings of which are incorporatedherein by reference. The CO₂ can generally be readily reacted withhydrogen gas using any conventional methanol synthesis catalyst, such asa zinc-chromium oxide catalyst or copper-zinc-alumina catalyst as knownin the art, to form methanol according to the following equation:

CO₂+3H₂→CH₃OH+H₂O

[0049] Hydrogen gas for the conversion may be obtained by taking aportion of the natural gas (either before or after pre-treatment toremove CO₂ and other acid gases, such as H₂S) and reforming it, such asby steam methane reforming, to produce a synthesis gas with a H₂ tocarbon oxide ratio favorable for efficient conversion to methanol.Generally, this stoichiometric molar ratio is expressed as follows:

S_(n)═[H₂—CO₂]/[CO+CO₂]

[0050] which is generally from 1.5 to 2.5 and more particularly 2.0 to2.1. As a result, CO₂ which would otherwise have been vented toatmosphere can be advantageously converted to higher value products,such as methanol and dimethyl ether.

[0051] An embodiment of the process disclosed in U.S. Ser. No.60/458,005 is illustrated in FIG. 1. Separation of the CO₂ from thenatural gas as produced from a reservoir is not shown on FIG. 1 forconvenience, but may be done by any of a number of methods known to theart and is briefly mentioned herein.

[0052] Typically, the CO₂ and other acid gases such as H₂S, as well asother contaminants such as mercaptans, mercury and water, are removed inconventional pre-treatment steps. Acid gases and mercaptans are commonlyremoved via a sorption process employing an aqueous amine-containingsolution or other types of known physical or chemical solvents. Aninhibited amine solution can be used to selectively remove the CO₂ inthe natural gas stream, but not H₂S gas. The H₂S gas can then be removedin a subsequent step. A substantial portion of the water is generallyremoved as a liquid through two-phase gas-liquid separation prior to orafter low level cooling of the natural gas, followed by molecular sieveprocessing for removal of trace amounts of water. Residual amounts ofwater and acid gases are most commonly removed through the use ofparticularly selected sorbent beds such as regenerable molecular sieves.Mercury is removed through use of mercury sorbent beds. The pretreatmentof the natural gas generally results in a treated natural gas having aCO₂ content of less than 0.1 mole percent, and more preferably less than0.01 mole percent, based on the total feed.

[0053] As shown in FIG. 1, all or a portion of the CO₂ recovered fromsuch pre-treatment steps may be conveyed by lines 8 and 10 and thencombined with a natural gas stream in line 4 to produce a blended feedstream which is conveyed by line 12 to a heater 20. After being heatedin heater 20, the blended feed stream is then conveyed by line 25 to aguard bed vessel 30 wherein any residual amount of sulfur-containingcontaminants present in the blended feed stream may be removed bycontact with an adsorbent bed, typically of zinc oxide. Alternatively,the CO₂ stream conveyed by lines 8 and 10 and natural gas streamconveyed by line 4 could be treated individually in such guard beds.

[0054] After treatment in the guard bed 30, steam is added to theblended feed stream via line 38. The blended feed stream is thenconveyed by line 35 to heater 40 wherein the temperature thereof isfurther adjusted to from 300° C. (572° F.) to 450° C. (842° F.) prior tointroducing the blended feed stream via line 45 to pre-reformer reactorvessel 50. Pre-reformer reactor vessel 50 typically contains anickel-based reforming catalyst, but may be any of a number of reformingcatalysts as known in the art, and is designed to convert higherhydrocarbons which may be present in the blended feed stream and producea predominately methane-containing feed stream. Effluent frompre-reformer reactor vessel 50 is conveyed by line 55 to a heater 70which heats the effluent to a temperature suitable for steam reformingof the methane-containing stream into synthesis gas, typically atemperature of from 400° C. (752° F.) to 500° C. (932° F.). In the eventthat the CO₂ feed in line 8 is substantially free of sulfur-containingcompounds, such as less than 1 ppm, it is possible to add CO₂ to theprocess at the location identified as 60 on FIG. 1, by conveying all orpart of the CO₂ to this location via line 58.

[0055] After being heated to a temperature suitable for steamreformation, the methane-containing stream is conveyed by line 75 tosteam reformer vessel 80. Steam reformer vessel 80 typically contains anickel-containing steam reforming catalyst, but may be any of thoseknown in the art, which converts the methane-containing stream into onerich in synthesis gas, i.e., hydrogen gas and carbon oxides. Thesynthesis gas stream exiting steam reformer vessel 80 is conveyed byline 85 to a heat exchanger 90 where excess heat therein is recoveredfor other uses, such as in heaters 20 and 40. The synthesis gas streamis then conveyed by line 95 to a cooler 100 wherein the temperature isfurther reduced. The so-cooled synthesis gas stream is conveyed by line105 to separator 110 wherein condensed water may be removed from theprocess by line 115. The synthesis gas stream is thereafter conveyed byline 120 to synthesis gas compressor 130 which compresses the stream toa pressure suitable for methanol production, such as 35 to 150 bar. Thecompressed synthesis gas stream is then conveyed by lines 135 and 140 toheat exchanger 150 wherein the temperature is adjusted to that suitablefor methanol production, such as from 200° C. (392° F.) to 300° C. (572°F.).

[0056] After adjustment of temperature, the synthesis gas stream isconveyed by line 155 to methanol synthesis reactor 160. Methanolsynthesis reactor 160 generally utilizes a catalyst, such as acopper-zinc-alumina catalyst as mentioned above, but may be any of thoseknown in the art. Effluent from the methanol synthesis reactor 160comprised primarily of methanol, water, and unreacted synthesis gas isconveyed by line 165 to heat exchanger 150 wherein excess heat isrecovered therefrom, and thereafter the effluent is conveyed by line 170to cooler 175. Thereafter, the effluent is conveyed by line 178 toseparator 180 wherein a crude methanol product is recovered through line210 and a gaseous stream exits by line 185. A purge gas stream, whichmay be used as fuel gas, is taken off via line 190 and the remainder ofthe gaseous stream comprised of unreacted synthesis gas is directed byline 195 to recycle compressor 200 which recompresses the gaseous streamto that suitable for methanol synthesis as previously described. Thecompressed gaseous stream is directed by line 205 to line 135 and mixedwith fresh synthesis gas.

[0057] The resulting methanol product from line 210 can then be purifiedby methods as known in the art, such as distillation, and then readilyconverted to DME as summarized on pages 538-539 of the Kirk-Othmerpassage previously incorporated herein. In general, DME is prepared bydehydrating methanol over an acidic catalyst to produce dimethyl etherand water.

[0058] While the foregoing process has been described in detail, itshould be understood that the DME can be derived from any other sourceor method known in the art, and that the natural gas component may bederived from LNG or simply comprise natural gas produced from asubterranean reservoir or formation with or without pretreatment toremove contaminants as described herein.

[0059] Where the DME is to be incorporated into the feed during theproduction of LNG products (which may be either in the vapor phase,liquid phase, or both), such that the DME and LNG are condensed in theLNG process to produce a blended liquid product comprised of LNG andDME, as illustrated generally by FIG. 2, the DME employed should besubstantially pure DME. By “substantially pure” in this instance, it ismeant that there should be less than 0.002 mol % of contaminants thereinbased on the total DME composition employed for blending, suchcontaminants typically being water and methanol that are present fromthe process used to produce the DME and which are typically present incommercial grades of DME. The DME material employed in this embodimentcan be distilled until reaching the desired DME purity level. Thecontaminants generally have a freezing point significantly higher thanthose of DME and methane, and as such would likely freeze and form anundesirable solid phase in the liquefaction process employed to producethe LNG. Furthermore, while DME has physical properties similar to LPGand might be expected to have a solubility in LNG similar thereto, inpractice it has been found that the DME has relatively limitedsolubility in liquid LNG. Typically, the foregoing method of condensingboth DME and LNG by a LNG type process is limited to applications whereonly a relatively minor change in heat value of the LNG product isdesired, such as production of a blended LNG/DME liquid product whereinthe amount of DME therein is 5 mol % or less of the total blendedproduct.

[0060] In accordance with the foregoing embodiment of the presentinvention, during production of LNG in a natural gas liquefactionprocess as previously mentioned, the DME component may be blended intothe feed stream to be liquefied in the LNG process at a point afterremoval of the NGLs, but before the methane gas stream is cooled toabout the freezing point of DME, i.e., about −220° F. (−140° C.). TheDME should be blended into the feed stream above a temperature of about−220° F. (−140° C.) so that a separate, solid phase of DME is not formedin the natural gas feed stream. Also, in this embodiment, it isimportant to maintain the DME content within feed stream being liquefiedbelow a saturation point so that the DME does not solidify and create aseparate solid phase. Generally, this concentration is about 5 mole %based on total amount of blended liquid product.

[0061]FIG. 2 illustrates in simple terms the method of blending of DMEinto natural gas during production of a LNG product in a natural gasliquefaction process according to the embodiment just mentioned.

[0062] Mixing of the DME and LNG product in the liquid phase afterproduction of the LNG is not desirable, due to the limited solubility ofthe DME therein, and also greater tendency of the DME to form anundesirable solid phase.

[0063] It is generally more favorable and convenient to mix the DME intoa natural gas component in the vapor phase. In this case, the naturalgas component may be a natural gas obtained by re-gasification of an LNGproduct, or it may be a natural gas obtained from another source, suchas by production from a subterranean reservoir, with or without the oneor more of the pre-treatment steps previously mentioned. If the DME isto be blended with the LNG after re-gasification, then a larger amountof such contaminants can be tolerated so long as the contaminants do notinhibit the intended use of such blend, as in for example, use as a fuelcomposition. Also, DME has physical properties similar to LPG, and thusit may be stored as a liquid under pressures similar to those used inconnection with storage of LPG. Just prior to use, the DME may bere-gasified, such as by reduction of pressure, and then mixed with thenatural gas component. Alternatively, the DME may be directly injectedand mixed with the re-gasified LNG.

[0064] In accordance with the foregoing embodiment of the inventionwherein DME is mixed with a natural gas component in the gas phase, theblending of the DME can be generally accomplished without significantattention to keeping the DME concentration relatively low. Therefore, itis not as important to employ substantially pure DME as previouslymentioned herein, and also the concentration of DME blended into thenatural gas is not limited to 5 mol %. As such, mixtures having arelatively larger amount of DME mixed with the natural gas component canbe prepared by this embodiment. Typically, in commercial practice and asa preferred embodiment of the invention, it would only necessary toblend in enough DME so that the ultimate, blended natural gas producthas a higher heating value which meets a consumer's specification, asthe DME is a higher value component relative to the natural gas. Typicaldesired heating values are mentioned herein. More importantly, the upperlimit for the amount of DME added will be that which allows theresulting fuel blend to be maintained below the hydrocarbon dew pointfor the pressure and temperature at which the fuel blend is to be storedor conveyed, typically those conditions being specified for the pipelinein which the fuel blend is to be conveyed to market or the ultimate userthereof. FIG. 5 shows that the hydrocarbon dew point for a selectedpipeline pressure varies based on the amount of DME added to the fuelblend. As such, the customer specification can usually be attained bypreferably blending in a minor amount of DME, such as less than 25 mol %based on the total fuel composition, generally less than 20 mol %, andbeneficially from 15 mol % to 10 mol % due to these considerations. Inthis embodiment, the DME may be conveniently added at any temperature upto the applicable dew point of the natural gas component employed sothat no liquids condense from the gas phase.

[0065] Mixing of the DME and natural gas component in the gas phaseaccording to this embodiment of the invention may be conducted in anyprocess vessel, such as a pipe or tank.

[0066]FIG. 3 illustrates in simple terms the blending of DME into anatural gas component derived from LNG in the vapor phase afterre-gasification of the LNG at, for example, a re-gasification facilitynear a market site for such gas product. Re-gasification methods for LNGare generally well-known in the art. Preferably, the DME employed willbe stored in a liquid state, which is also more convenient andeconomical for transport of the DME composition to a market site, andthen the DME is re-gasified prior to or during blending with there-gasified LNG. Re-gasification methods for LNG can also be used tore-gasify the DME. Further, such re-gasification methods can also beused to re-gasify a DME/LNG blend which is in a liquid state accordingto the aspect of the invention previously mentioned.

[0067] A particular blended DME/LNG liquid product, in accordance withthe present invention, generally comprises:

[0068] less than 2 mole percent nitrogen and preferably less than 1 molepercent nitrogen;

[0069] less than 1 mole percent and preferably less than 0.5 molepercent helium;

[0070] less than 3 mole percent and preferably less than 1.5 molepercent of the total of nitrogen and helium; and

[0071] less than 5 mole percent and preferably less than 4 mole percentof DME within the blended liquid product.

[0072] Where the DME is blended into a regasified LNG product, accordingto one aspect of the invention, the resulting fuel blend preferablycomprises:

[0073] less than 0.3 mole percent nitrogen and preferably less than 0.2mole percent nitrogen;

[0074] less than 0.2 mole percent and preferably less than 0.1 molepercent helium;

[0075] less than 0.5 mole percent and preferably less than 0.2 molepercent of the total of nitrogen and helium; and

[0076] less than 25 mol % DME, based on the total fuel blend, typicallyless than 20 mol %, and beneficially from 10 to 15 mol % DME based onthe total fuel blend.

[0077] A typical gross heating value for the fuel composition producedin accordance with the present invention generally ranges from about1000 Btu/scf to about 1200 Btu/scf, and more typically from about 1030Btu/scf to about 1170 Btu/scf, and particularly from about 1050 BTU/scfto about 1150 BTU/scf.

[0078] Further, rather than converting methanol to DME, as discussedhereinabove, it is also possible to convert methanol to olefins, such aspropene, by well known methanol-to-olefin (MTO) processes, such as thoseprocesses described in U.S. Pat. Nos. 6,534,692; 6,455,747, and5,714,662, the teachings of which are incorporated herein by reference.The olefin products may then be blended into a lean natural gas, are-gasified LNG product, or incorporated into an LNG process to increasethe heating value of LNG produced therein, substantially in accordancewith the present invention. Additionally, the olefin products may behydrogenated to produce alkanes, such as propane, by well known olefinhydrogenation processes. The resulting alkanes, such as propane, mayalso be mixed with a lean natural gas, a re-gasified LNG product, orotherwise incorporated into an LNG process to increase the heating valueof LNG produced therein, substantially in accordance with the presentinvention.

SPECIFIC EMBODIMENTS OF THE INVENTION

[0079] The present invention is described in further detail inconnection with the following examples, it being understood that thesame is for purposes of illustration and not limitation.

COMPARATIVE EXAMPLE A

[0080] In Comparative Example A, the heating value of an LNG compositionprepared from a lean natural gas composition is determined according tostandard measurements and calculations. The LNG is prepared by acascade-type LNG process. The composition of the LNG product is shown inthe table of FIG. 4, wherein the methane content is shown to be 97.01mol %, with a small amount of ethane (1.80 mol %) and even smalleramounts of other light hydrocarbons therein. The heating value of thelean natural gas is about 1025 BTU/scf. The column labeled “A” in FIG. 4contains data associated with Comparative Example A.

EXAMPLES 1-2

[0081] Examples 1-2 are blends of a substantially pure DME with the LNGproduct of Comparative Example A, prepared in accordance with thepresent invention.

[0082] For Example 1, the mixing of the DME is conducted by injectingthe DME into the LNG process downstream of any heavy hydrocarbon (butaneand heavier) removal operation, but upstream of where the LNGtemperature is lowered at or below the normal freezing point of pureDME, about −140° C. at atmospheric pressure. The LNG and injected DMEare mixed well and thereafter cooled to a temperature below −140° C. tosubstantially liquefy the DME and hydrocarbons therein. The amount ofDME injected is sufficient to result in a blended liquid product whereinthe DME is about 5 mole percent based on the total liquid product. Thedata for the resulting liquid product is shown on FIG. 4 in the columnlisted as “Ex. 1”. The liquid product is produced at a temperature ofabout −162° C. (−262° F.) and substantially atmospheric pressure (14.7psia).

[0083] For Example 2, the DME is blended with re-gasified LNG at apressure of 500 psia and temperature of about 15° C. (60° F.). Data forthe resulting vapor phase fuel blend is shown in FIG. 4 in the columnlisted as “Ex. 2”. Blending at higher temperatures and in the vaporstate allows for higher DME blend concentrations without DMEsolidification as previously described herein.

COMPARATIVE EXAMPLES B-C

[0084] Comparative Examples B-C concern preparation of blendssubstantially according to the procedures of Examples 1-2, except thatpropane is blended rather than DME. The columns labeled “B” and “C” inFIG. 4 corresponds to data associated with Comparative Examples B-C.

EXAMPLE 3

[0085] For Example 3, the procedure of Example 2 is substantiallyrepeated, except that the DME is added in an amount sufficient to yielda fuel blend having 10 mol % DME based on the total fuel blend. The dataassociated with Example 3 is shown in FIG. 4 under the column listed“Ex. 3”.

COMPARATIVE EXAMPLE D

[0086] For Comparative Example D, the procedure of Comparative Example Cis substantially repeated, except that the amount of propane added is anamount sufficient to yield a blend having 10 mol % propane based on thetotal blend. The data associated with Comparative Example D is shown inFIG. 4 under the column listed as “D”.

[0087] As can be seen, the present invention relates to alternativeproducts and methods which may be used to provide more economical andconvenient fuel compositions having improved heating values.

We claim:
 1. A composition comprising natural gas and dimethyl ether. 2.The composition of claim 1 wherein the natural gas is a lean naturalgas.
 3. The composition of claim 2 wherein the lean natural gascomprises less than about 3 mol % of C₂ to C₅ hydrocarbons with thebalance of the hydrocarbons in the lean natural gas being essentiallymethane, based on the total composition.
 4. The composition of claim 1wherein dimethyl ether is present in an amount of less than 25 mol %based on the total composition.
 5. The composition of claim 1 whereindimethyl ether is present in an amount of less than 20 mol % based onthe total composition.
 6. The composition of claim 1 wherein dimethylether is present in an amount of from 10 mol % to 15 mol % based on thetotal composition.
 7. The composition of claim 1 wherein the natural gasis derived from a regasified LNG product produced in an LNG process. 8.The composition of claim 1 having a heating value of from about 1000BTU/scf to about 1200 BTU/scf.
 9. The composition of claim 1 having aheating value of from about 1030 BTU/scf to about 1170 BTU/scf.
 10. Thecomposition of claim 1 having a heating value of from about 1050 BTU/scfto about 1150 BTU/scf.
 11. A method for preparing a fuel blendcomprising natural gas and dimethyl ether, the method comprising mixinga natural gas component and dimethyl ether.
 12. The method of claim 11wherein the natural gas component is derived from a regasified LNGproduct prepared in a LNG process.
 13. The method of claim 12 furthercomprising: pre-treating a natural gas stream comprising acid gases,water and other contaminants therein to remove at least a portion of thecontaminants therefrom and provide a natural gas feed; cooling thenatural gas feed in the LNG process to liquefy at least a portion of thenatural gas component and thereby produce a LNG product; andre-gasifying the LNG product to obtain the natural gas component. 14.The method of claim 13 further comprising: providing dimethyl ether; andmixing the dimethyl ether with the natural gas component to obtain thefuel blend.
 15. The method of claim 14 wherein mixing of the natural gascomponent and dimethyl ether occurs at a site remote from the locationwhere the natural gas stream originates.
 16. The method of claim 12wherein the dimethyl ether is blended in an amount such that theconcentration of dimethyl ether in the fuel blend is less than 25 mol %based on the total fuel blend.
 17. The method of claim 12 wherein thedimethyl ether is blended in an amount such that the concentration ofdimethyl ether in the fuel blend is less than 20 mol % based on thetotal fuel blend.
 18. The method of claim 12 wherein the dimethyl etheris blended in an amount such that the concentration of dimethyl ether inthe fuel blend is from 10 mol % to 15 mol % based on the total fuelblend.
 19. The method of claim 12 wherein the fuel blend has a heatingvalue of from about 1000 BTU/scf to about 1200 BTU/scf.
 20. The methodof claim 12 wherein the fuel blend has a heating value of from about1030 BTU/scf to about 1170 BTU/scf.
 21. The method of claim 12 whereinthe fuel blend has a heating value of from about 1050 BTU/scf to about1150 BTU/scf.
 22. The method of claim 11 further comprising:pre-treating a natural gas stream comprising acid gases, water and othercontaminants therein to remove at least a portion of the contaminantstherefrom and provide a natural gas feed for a LNG process; mixing thedimethyl ether into the natural gas feed within a LNG process at atemperature above −220° F. (−140° C.) and in an amount such that thedimethyl ether does not solidify and form a separate solid phase duringliquefaction of the natural gas feed in the LNG process; and cooling theresulting natural gas and dimethyl ether mixture within the LNG processto a temperature of from about −240° F. (−151° C.) to about −260° F.(−162° C.) or less so as to liquefy at least a portion of the mixtureand thereby produce a blended liquid product at substantiallyatmospheric pressure; and re-gasifying the blended liquid product toproduce the fuel blend.
 23. The method of claim 22 wherein the fuelblend comprises dimethyl ether in an amount of 5 mole % or less based onthe total fuel blend.
 24. A method for preparing a fuel blend comprisingnatural gas and dimethyl ether, the method comprising: pre-treating anatural gas stream comprising acid gases, water and other contaminantstherein to remove at least a portion of the contaminants therefrom andprovide a natural gas feed; cooling the natural gas feed in a LNGprocess to liquefy at least a portion of the natural gas component andthereby produce a LNG product; providing dimethyl ether; re-gasifyingthe LNG product to obtain the natural gas component; and mixing thedimethyl ether with the natural gas component to obtain the fuel blend.